A number of hydrocarbons, especially lower-boiling light hydrocarbons in formation fluids or natural gas are known to form hydrates in conjunction with water present under a variety of conditions—particularly at the combination of lower temperature and higher pressure. The hydrates usually exist in solid forms that are essentially insoluble in the fluid itself. The solid hydrates may cause issues for production, handling, and transport of these fluids. For example, hydrate solids (or crystals) may cause plugging and/or blockage of pipelines, transfer lines, other conduits, valves, safety devices, and/or other equipment, which may result in shutdown, loss of production, risk of explosion, or unintended release of hydrocarbons into the environment either on-land or off-shore.
Hydrocarbon hydrates are clathrates, which are cage structures formed between a host molecule and a guest molecule. A hydrocarbon hydrate may be composed of crystals formed by water host molecules surrounding the hydrocarbon guest molecules. The smaller or lower-boiling hydrocarbon molecules, particularly C1 (methane) to C4 hydrocarbons and their mixtures, may be more problematic because their hydrate or clathrate crystals may be easier to form.
The guest molecules trapped in hydrates typically may be hydrocarbon gases, such as methane, ethane, propane, butane and isobutane. Alkenes, alkynes, methyl substituted butanes and pentanes, cyclic alkanes from cyclopropane to cyclooctane, cycloalkenes and their methyl-substituted analogs may also be present as guest molecules. Other possible guests in natural hydrates are small molecules, such as CO2, H2S, the noble gases (Ar, Kr, Xe), oxygen and nitrogen. Such clathrate hydrates can also be formed in laboratory and industrial settings as well as clathrate hydrates formed by ethers, ketones, aldehydes, mercaptans, sulfides, halogenated hydrocarbons, and a number of inorganic molecules including, but not limited to, SF6, PH3, H2Se, SO2, ClO2, CO, ClO3F, SO2F2, NF3, Cl2, Br2, and COS. Even certain non-hydrocarbons, such as carbon dioxide, nitrogen and hydrogen sulfide are known to form hydrates under certain conditions.
Thermodynamic and kinetic techniques may be used to overcome or control the hydrocarbon hydrate problems. For the thermodynamic approach, there are a number of reported or attempted methods, including water removal, increasing temperature, decreasing pressure, addition of “antifreeze” additives to the fluid and the like. The kinetic approach generally attempts (a) to prevent the smaller hydrocarbon hydrate crystals from agglomerating into larger ones and/or (b) to inhibit and/or retard initial hydrocarbon hydrate crystal nucleation; and/or crystal growth.
Another problem in oil drilling and exploration involves the formation of scale. Scale is a deposit or coating formed on the surface of metal, rock or other materials. Scale formation may be caused by a precipitation from a chemical reaction with the surface, precipitation caused by chemical reactions, a change in pressure or temperature, or a change in the composition of a solution. Typical scales are calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, iron sulfide, iron oxides, iron carbonate, various silicates and phosphates and oxides, or any of a number of compounds insoluble or slightly soluble in water.
Hydrate and/or scale formation are deleterious in many downhole fluids, such as drilling fluids, completion fluids, servicing fluids (e.g. fracturing fluids), production fluids, injection fluids, and combinations thereof. Drilling fluids are typically classified according to their base fluid. In water-based fluids, solid particles, such as weighting agents, are suspended in a continuous phase consisting of water or brine. Oil can be emulsified in the water, which is the continuous phase. “Water-based fluid” is used herein to include fluids having an aqueous continuous phase where the aqueous continuous phase can be all water or brine, an oil-in-water emulsion, or an oil-in-brine emulsion. Brine-based fluids, of course are water-based fluids, in which the aqueous component is brine.
Oil-based fluids are the opposite or inverse of water-based fluids. “Oil-based fluid” is used herein to include fluids having a non-aqueous continuous phase where the non-aqueous continuous phase is all oil, a non-aqueous fluid, a water-in-oil emulsion, a water-in-non-aqueous emulsion, a brine-in-oil emulsion, or a brine-in-non-aqueous emulsion. In oil-based fluids, solid particles are suspended in a continuous phase consisting of oil or another non-aqueous fluid. Water or brine can be emulsified in the oil; therefore, the oil is the continuous phase. In oil-based fluids, the oil may consist of any oil or water-immiscible fluid that may include, but is not limited to, diesel, mineral oil, esters, refinery cuts and blends, or alpha-olefins. Oil-based fluid as defined herein may also include synthetic-based fluids or muds (SBMs), which are synthetically produced rather than refined from naturally-occurring materials. Synthetic-based fluids often include, but are not necessarily limited to, olefin oligomers of ethylene, esters made from vegetable fatty acids and alcohols, ethers and polyethers made from alcohols and polyalcohols, paraffinic, or aromatic, hydrocarbons alkyl benzenes, terpenes and other natural products and mixtures of these types.
There are a variety of functions and characteristics that are expected of completion fluids. The completion fluid may be placed in a well to facilitate final operations prior to initiation of production. Completion fluids are typically brines, such as chlorides, bromides, and/or formates, but may be any non-damaging fluid having proper density and flow characteristics. Suitable salts for forming the brines include, but are not necessarily limited to, sodium chloride, calcium chloride, zinc chloride, potassium chloride, potassium bromide, sodium bromide, calcium bromide, zinc bromide, sodium formate, potassium formate, ammonium formate, cesium formate, and mixtures thereof. Chemical compatibility of the completion fluid with the reservoir formation and formation fluids is key. Chemical additives, such as polymers and surfactants are known in the art for being introduced to the brines used in well servicing fluids for various reasons that include, but are not limited to, increasing viscosity, and increasing the density of the brine. Completion fluids do not contain suspended solids.
Production fluid is the fluid that flows from a formation to the surface of an oil well. These fluids may include oil, gas, water, as well as any contaminants (e.g. H2S, asphaltenes, etc.). The consistency and composition of the production fluid may vary.
Refinery fluids are fluids that may be further processed or refined at a refinery. A non-limiting example of a refinery process may include reducing or preventing the formation of foulants. Non-limiting examples of foulants may be or include hydrates, asphaltenes, coke, coke precursors, naphthenates, inorganic solid particles (e.g. sulfates, oxides, scale, and the like), and combinations thereof. Non-limiting examples of refinery fluids include crude oil, production water, and combinations thereof.
Servicing fluids, such as remediation fluids, stimulation fluids, workover fluids, and the like, have several functions and characteristics necessary for repairing a damaged well. Such fluids may be used for breaking emulsions already formed and for removing formation damage that may have occurred during the drilling, completion and/or production operations. The terms “remedial operations” and “remediate” are defined herein to include a lowering of the viscosity of gel damage and/or the partial or complete removal of damage of any type from a subterranean formation. Similarly, the term “remediation fluid” is defined herein to include any fluid that may be useful in remedial operations. A stimulation fluid may be a treatment fluid prepared to stimulate, restore, or enhance the productivity of a well, such as fracturing fluids and/or matrix stimulation fluids in one non-limiting example.
Hydraulic fracturing is a type of stimulation operation, which uses pump rate and hydraulic pressure to fracture or crack a subterranean formation in a process for improving the recovery of hydrocarbons from the formation. Once the crack or cracks are made, high permeability proppant relative to the formation permeability is pumped into the fracture to prop open the crack. When the applied pump rates and pressures are reduced or removed from the formation, the crack or fracture cannot close or heal completely because the high permeability proppant keeps the crack open. The propped crack or fracture provides a high permeability path connecting the producing wellbore to a larger formation area to enhance the production of hydrocarbons.
The development of suitable fracturing fluids is a complex art because the fluids must simultaneously meet a number of conditions. For example, they must be stable at high temperatures and/or high pump rates and shear rates that can cause the fluids to degrade and prematurely settle out the proppant before the fracturing operation is complete. Various fluids have been developed, but most commercially used fracturing fluids are aqueous based liquids that have either been gelled or foamed to better suspend the proppants within the fluid.
Injection fluids may be used in enhanced oil recovery (EOR) operations, which are sophisticated procedures that use viscous forces and/or interfacial forces to increase the hydrocarbon production, e.g. crude oil, from oil reservoirs. The EOR procedures may be initiated at any time after the primary productive life of an oil reservoir when the oil production begins to decline. The efficiency of EOR operations may depend on reservoir temperature, pressure, depth, net pay, permeability, residual oil and water saturations, porosity, fluid properties, such as oil API gravity and viscosity, and the like.
EOR operations are considered a secondary or tertiary method of hydrocarbon recovery and may be necessary when the primary and/or secondary recovery operation has left behind a substantial quantity of hydrocarbons in the subterranean formation. Primary methods of oil recovery use the natural energy of the reservoir to produce oil or gas and do not require external fluids or heat as a driving energy; EOR methods are used to inject materials into the reservoir that are not normally present in the reservoir.
Secondary EOR methods of oil recovery inject external fluids into the reservoir, such as water and/or gas, to re-pressurize the reservoir and increase the oil displacement. Tertiary EOR methods include the injection of special fluids, such as chemicals, miscible gases and/or thermal energy. The EOR operations follow the primary operations and target the interplay of capillary and viscous forces within the reservoir. For example, in EOR operations, the energy for producing the remaining hydrocarbons from the subterranean formation may be supplied by the injection of fluids into the formation under pressure through one or more injection wells penetrating the formation, whereby the injection fluids drive the hydrocarbons to one or more producing wells penetrating the formation. EOR operations are typically performed by injecting the fluid through the injection well into the subterranean reservoir to restore formation pressure, improve oil displacement or fluid flow in the reservoir, and the like.
Examples of EOR operations include water-based flooding and gas injection methods. Water-based flooding may also be termed ‘chemical flooding’ if chemicals are added to the water-based injection fluid. Water-based flooding may be or include, polymer flooding, ASP (alkali/surfactant/polymer) flooding, SP (surfactant/polymer) flooding, low salinity water and microbial EOR; gas injection includes immiscible and miscible gas methods, such as carbon dioxide flooding, and the like.
It would be desirable if additives were developed for fluid compositions used during hydrocarbon recovery to depress the freezing point of the fluid compositions.